Range Resources Company Presentation - April 28, 2014
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Range Resources Company Presentation - April 28, 2014

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A PowerPoint presentation from Range reviewing recent production and developments, delivered as part of their 1Q14 update. Lots of great information. In particular, MDN likes the following slides: 7, ...

A PowerPoint presentation from Range reviewing recent production and developments, delivered as part of their 1Q14 update. Lots of great information. In particular, MDN likes the following slides: 7, 11, 12-17, 31, 51, 53, 56. Take time to review the entire thing!

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Range Resources Company Presentation - April 28, 2014 Range Resources Company Presentation - April 28, 2014 Presentation Transcript

  • 1 April 28, 2014 Range Resources Corporation Company Presentation
  • 2 Forward-Looking Statements Statements concerning well drilling and completion costs assume a development mode of operation; additionally, estimates of future capital expenditures, production volumes, reserve volumes, reserve values, resource potential, resource potential including future ethane extraction, number of development and exploration projects, finding costs, operating costs, overhead costs, cash flow, NPV10, EUR and earnings are forward-looking statements. Our forward looking statements, including those listed in the previous sentence are based on our assumptions concerning a number of unknown future factors including commodity prices, recompletion and drilling results, lease operating expenses, administrative expenses, interest expense, financing costs, and other costs and estimates we believe are reasonable based on information currently available to us; however, our assumptions and the Company’s future performance are both subject to a wide range of risks including, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes, and there is no assurance that our projected results, goals and financial projections can or will be met. This presentation includes certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our website at www.rangeresources.com. The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as "resource potential," or "unproved resource potential,” "upside" and “EURs per well” or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven, unrisked resource potential has not been fully risked by Range's management. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800- SEC-0330. 2
  • 3 Range Resources Strategy  Focus on PER SHARE GROWTH of production and reserves at top-quartile or better cost structure while high grading the inventory  Maintain simple, strong financial position  Operate safely and be a good steward of the environment Proven track record of performance Marcellus Shale 41 to 51Tcfe resource potential Upper Devonian Shale 12 to 18 Tcfe resource potential Utica/Point Pleasant Shale Midcontinent Mississippian, St. Louis, Cana Woodford, Granite Wash 7 to 10 Tcfe resource potential West Texas Wolfcamp, Cline Shale, Wolfberry 1 to 2 Tcfe resource potential Nora Area Huron Shale, Berea, Big Lime, CBM 3 to 4 Tcfe resource potential Total Resource Potential 64 to 85 Tcfe without Utica/Point Pleasant Shale 3
  • 4 Range – Significant Growth Model for Many Years  2014 production growth expected to be 20%-25%  High rate of return, high growth, large scale assets  Solid track record of execution, planning, marketing and logistics  Low cost structure  Resource potential 8-10 times proved reserves*  Strong financial position 4 *Without quantifying Utica/Point Pleasant Potential
  • 5 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2008 2009 2010 2011 2012 2013 5 10 15 20 25 30 35 40 45 50 2008 2009 2010 2011 2012 2013 Range is Focused on Per Share Growth, on a Debt-Adjusted Basis Production/share – debt adjusted Reserves/share – debt adjusted  Production/share = annual production divided by debt-adjusted year-end diluted shares outstanding  Reserves/share = year-end proven reserves divided by debt-adjusted year-end diluted shares outstanding Mcfe/share Mcfe/share 5 2013 Increase of 26% 2013 Increase of 25%
  • 6 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 Unit Costs Are a Key Focus $/mcfe (1) Three-year average of drill bit F&D costs, excluding acreage (2) Excludes non-cash stock compensation (3) Excludes retroactive payments for PA impact fee in 2012. 2008 2009 2010 2011 2012 2013 Reserve Replacement(1) $1.64 $1.25 $0.83 $0.68 $0.68 $0.66 LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41 $0.37 Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15(3) $0.13 G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46 $0.42 Interest $0.71 $0.74 $0.73 $0.69 $0.61 $0.51 Trans. & Gathering $0.08 $0.32 $0.40 $0.62 $0.70 $0.75 Total $4.30 $3.84 $3.42 $3.29 $3.01 $2.84 $0.00 6
  • 7 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 Lease Operating Expense G&A Expense Interest Expense PUD Adjustment 3-Year Reserve Replacement 7 Range – #2 Low Cost Producer in 2012 $/Mcfe Source: Bank of America Securities 2012 E&P Full-Cycle Margin & Reserve Digest supplemented with Range peer group. * Peer group company added ** Three-year reserve replacement cost not meaningful due to negative reserve revisions, or data extents beyond the graph Note: LOE includes production taxes, gathering, & transportation; Interest includes preferred dividends and capitalized interest; and G&A expense excludes equity-based compensation ** 1st, 2nd, or 3rd in the Bank of America Study for Each of the Last 9 Years Range Resources
  • 8 Financial Position  Strong, Simple Balance Sheet – Bank debt, subordinated notes and common stock – No debt maturity until 2016 (bank) and 2019 (notes) – Available liquidity of $1.0 billion under commitment amount  Well Structured Bank Credit Facility – 28 banks with no bank holding more than 9% of total – Current borrowing base of $2.0 billion; commitment amount of $1.75 billion – Expect to maintain or improve Ba1/BB corporate rating during growth  Solid Hedge Position – Range typically hedges a significant portion of upcoming 12 months of production – For 2014, over 80% of projected production is hedged – For 2015, over 30% of projected production is hedged – Hedging in 2016 has started 8
  • 9 Moved 6.4 Tcfe of Resource Potential into Proved Reserves in the Last Four Years (1) Proforma 3.5 Tcfe after Barnett sale (2) Net unproved resource potential. (3) Added 12 – 15 Tcfe resource potential for tighter spaced drilling in the wet and super-rich Marcellus to YE 2012 resource potential at mid-year 2013 9 Tcfe YE 2009 YE 2010 YE 2011 YE 2012 YE 2013 Proved Reserves 3.1 4.4(1) 5.1 6.5 8.2 Resource Potential (2) 24 - 32 35 - 52 44 - 60 48 – 68(3) 64 - 85 Proved reserves have increased by 28% per year on a compounded basis since 2009
  • 10 Resource Potential is 8 to 10 Times Proved Reserves Resource Area Gas (Tcf) Liquids (Mmbbls) Net Unproven Resource Potential (Tcfe) Marcellus Shale 27 – 35 2,250 – 2,740 41 – 51 Upper Devonian Shale 8 – 12 600 – 940 12 – 18 Midcontinent, Nora and Permian 6 – 8 800 – 1,260 11 – 16 TOTAL 41 – 54 3,650 – 4,940 64 – 85 As of 12/31/2013 – Does not include Utica/PP or tighter spacing in dry Marcellus areas; Liquids include Ethane 10
  • 11 ~1 Million Net Acres Prospective for Shales in PA Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013) (1) Approximately 140,000 acres prospective for Marcellus; ~175,000 acres prospective for wet Utica/Point Pleasant. (2) Extends partially into WV. Northwest 305,000 net acres(1) (Legacy acreage is largely held by shallow production) Southwest 530,000 net acres(2) (95% of acreage is HBP or projected to be drilled under existing lease terms) Northeast 120,000 net acres (One rig is projected to hold all blocked up acreage being targeted for development)
  • 12 Pennsylvania Stacked Pays – Net Acreage Upper Devonian 12 330,000 230,000 560,000 470,000 320,000 790,000 175,000 400,000 575,000 975,000 950,000 1,925,000 Stacked pays allow for multiple development opportunities at 1,000 foot spacing between wells and later with 500 foot spacing prospective on most acreage Marcellus Utica/Point Pleasant Wet Acreage Dry Acreage Total Acreage
  • 13 Gas In Place (GIP) – Marcellus Shale Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2013), and estimated as prospective, are outlined green. GIP – Range estimates. • GIP is a function of pressure, temperature, thermal maturity, porosity, hydrocarbon saturation and net thickness • Two core areas have developed in the Marcellus • Condensate and NGLs are in gaseous form in the reservoir
  • 14 Gas In Place (GIP) – Upper Devonian Shale Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2013), and estimated as prospective, are outlined green. GIP – Range estimates. • The greatest GIP in the Upper Devonian is found in SW PA • A significant portion of the GIP in the Upper Devonian is located in the wet gas window
  • 15 Gas In Place (GIP) – Utica/Point Pleasant Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2013), and estimated as prospective, are outlined green. GIP – Range estimates. The greatest GIP in the Utica/Point Pleasant is in the dry gas window in SW PA
  • 16 Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA When GIP analysis from the Marcellus, Upper Devonian and Utica/Point Pleasant are combined, the largest stacked pay resource is located in SW PA where Range has concentrated its acreage position Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2013), and estimated as prospective, are outlined green. GIP – Range estimates.
  • 17 Southwest PA – Range’s 530,000 Net Acres  Approximately 2,300 industry wells (1,700 horizontal & 600 vertical) have defined the productive boundaries of the Marcellus  Range’s acreage is highly prospective for Marcellus, with low reinvestment risk and high rates of return  Up to nine years of production history from this area Note: Townships where Range holds ~3,000 or more acres are shown in yellow (As of 12/31/2013) 17
  • 18 Small Percentage of Acreage Drilled ▪ Prospective acreage 530,000 ▪ Assumed spacing ~80 acres ▪ Potential Marcellus Shale locations 6,625 ▪ Producing horizontal wells ~540 ▪ Drilled wells divided by potential locations ~8% Southwest PA – Large Upside Potential ~670 Mmcfe/d net being produced from ~8% of Range’s acreage in SW PA 18
  • 19 19 Super-Rich Wet Dry EUR 2.05 Mmboe (12.3 Bcfe) 1,172 Mbbls & 5.3 Bcf 12.3 Bcfe 978 Mbbls & 6.4 Bcf 13.4 Bcf EUR/1,000 ft lateral 0.39 Mmboe (2.32 Bcfe equivalent) 2.93 Bcfe 2.58 Bcf EUR/stage 78.8 Mboe (473 Mmcfe equivalent) 586 Mmcfe 515 Mmcf Well Cost $6.8 MM $6.1 MM $6.6 MM Stages 26 21 26 Lateral Length 5,300 ft 4,200 ft 5,200 ft IRR – Strip 104% 107% 117% IRR – $4.00 105% 105% 104% Southwest PA – Development Mode Economic Summary With the robust returns from all SW PA areas, Range will be taking a balanced approach to developing acreage and growing overall production at 20% to 25% each year
  • 20 Innovative Gas Marketing 20  SW PA has better infrastructure  Range has added ~40 new customers since 2012 in the South, Southeast, Mid-Atlantic and Midwest  85% to 90% of Range’s 2014 expected volumes are tied to favorable indices  Marcellus differentials were $(0.06), $(0.11) and $0.88 for 3Q13, 4Q13 and 1Q14.
  • 21 21 Projected 2014 Projected 2016 Regional Direction Mmbtu/day Transport Cost per Mmbtu Mmbtu/day Transport Cost per Mmbtu Projected Pricing Indices Firm Transportation Local PA/OH 380,000 $ 0.21 430,000 $ 0.21 NYMEX, 219, TCO, DTI, M2, Leidy Northeast 230,000 $ 0.51 230,000 $ 0.51 NYMEX, NNY, M3 Midwest -- -- 200,000 $ 0.32 NYMEX, CCG, Michcon Gulf Coast/Southeast 260,000 $ 0.29 335,000 $ 0.26 NYMEX, CGT Firm Sales 240,000 -- 530,000 -- All of the above Total Take-Away Capacity 1,110,000 $ 0.25 1,725,000 $ 0.21 Marcellus Gas Marketing Arrangements We believe these firm arrangements provide adequate capacity to meet our growth projections through 2016.
  • 22 Mariner West ATEX Mariner East Innovative NGL Marketing – Domestically & Globally Appalachia has significant existing and growing petrochemical demand for NGLs from the Mid-West to up-state New York and along the Atlantic coastal industrial centers. Range has the option to sell into the local markets or has the option to export liquids out of the Marcus Hook harbor. Generally prices get an uplift since the pricing alternative is transporting liquids from Gulf Coast. Existing Pipeline Contractual Agreements (gross):  Mariner West – 15,000 bbl/d of ethane  ATEX – 10,000 bbl/d, increasing to 20,000 bbl/d of ethane  Mariner East – 20,000 bbl/d of ethane – 20,000 bbl/d of propane Ethane export to Canada 2013 Ethane pipeline to Mont Belvieu markets 2014 22 Propane/Ethane can be tied into NE markets or be exported in 2015 As NGL production increases, the Marcus Hook export facilities will allow Range to move its liquids to domestic and global markets which gives Range alternative pricing opportunities.
  • 23 23 Current Capability of Range’s Marcellus Area Processing Plant 1.8 Bcf/d of wet inlet gas 1.4 Bcf/d gas 55,000 bbls/d ethane 140,000 bbls/d condensate and C3+ 2.6 Bcfe/d > 1.0 Bcf/d > 3.6 Bcfe/d from the Marcellus (> 3.0 Bcfe/d net) Additional dry gas: Ethane contracts have cleared a path, allowing Range to produce over 3 Bcfe per day net from the Marcellus alone Inlet gas needed to produce 55,000 bbls ethane per day, assuming minimum extraction
  • 24 Additional Upside – Appalachia Stacked Pays 24 As Marcellus drilling holds all depths, industry activity is proving up our SW PA Utica/Point Pleasant and Upper Devonian acreage  Significant acreage positions in two areas SW PA – dry gas (400,000 net acres) NW PA – wet gas (175,000 net acres)  Utica/Point Pleasant test in Washington Co. planned to spud in 2Q2014  Significant offset wells being drilled to the east Utica/Point Pleasant Upper Devonian Shale  Upper Devonian acreage significantly derisked  Latest Super-Rich well – 24 hour test rate 10.0 Mmcfe/d (4.0 Mmcf/d gas, 172 bbls condensate, 826 bbls NGLs)  Co-development of Upper Devonian & Marcellus may result in enhanced Marcellus wells Stacked Pay Enhances Project Economics Note: Townships where Range holds ~3,000 or more acres are shown in yellow (As of 12/31/2012)
  • 25 Additional Upside – Oil Component Mississippian Chat Permian 25  ~160,000 net acres along the Nemaha Uplift  Successfully drilled the southern width of the Nemaha Uplift  Drilled highest oil rate well ever by Range – 24 hr IP of 1,263 boe (1,062 oil) per day  Successfully drilled 12 mile northern step out well; 30 day production rate of 330 boe per day with 94% liquids (85% oil, 9% NGLs)  Assuming 80 acre spacing would result in over 2,000 well locations  Currently being marketed  Stacked pay potential: Upper/Middle/Lower Wolfcamp, Cline  Surrounding industry activity is successfully drilling offset acreage with multiple targeted horizons  Drilled ~7,000 foot lateral wells in both the Upper Wolfcamp and Cline Two Potentially Large Scale, Repeatable Oil Projects are being tested
  • 26 New Markets Increasing Demand for Natural Gas Demand for natural gas could increase up to 20 Bcf per day by 2018(2)  Power Generation Sector  Utilities using more gas versus coal, by 2035 natural gas will surpass coal as leading electricity source (1)  Estimates say that natural gas fired power plants will supply 46% of all new power plant additions through 2035- compared to 37% for renewables, 12% for coal and 3% for nuclear (1)  Manufacturing/Petrochemical  Due to the large price difference in naptha (oil-based) versus ethane (gas-based), U.S. international petrochemical companies are converting their feedstocks from naptha to ethane  IHS chemical estimates $125 billion in announced U.S. petrochemical investments. (3)  Large number of proposed projects in gas-to-liquids, methanol, ethylene crackers and fertilizers  Natural Gas Exports  The outlook has changed from the U.S. being a net importer of natural gas to becoming a net exporter  To date, six LNG export facilities have been approved(4), representing 10 Bcf/day of additional demand  Natural gas exports would be beneficial for the U.S. under any pricing scenario. “Across all these scenarios, the U.S. was projected to gain net economic benefits from allowing LNG exports” (4)  Current proposed and announced export projects total 38.5 Bcf/day (5)  Transportation Sector  With natural gas vehicles (NGV’s) being 25% cleaner, fuel costs 50% less and new refueling stations being added across the U.S., the number of U.S. NGV’s is expected to increase significantly  Fleet managers at AT&T, UPS, and Waste Management are converting all or parts of their fleets to natural gas as are transit agencies, municipalities and state governments  The three largest U.S. truck manufacturers are now producing dual-fuel CNG trucks  Range now has 184 CNG vehicles in its own corporate fleet 26 1. EIA 2. Goldman Sachs 3. Wall St. Journal, 3/24/14 4. Department of Energy 5. DOE/FE LNG Applications
  • 27 27  Environmental, Health and Safety issues can affect many aspects of our business. Range feels a deep responsibility to protect our employees, contractors, the public and the environment. It is held as a core value.  Examples where Range has been a leader − In 2008, Range recommended improved standards for well cementing and casing to the DEP that are now being widely used. − In 2009, Range pioneered water recycling for shale gas development and we were the first company to achieve 100 percent reuse levels. − In 2010, Range was the first company to voluntarily disclose fluids used in hydraulic fracturing on a per well basis and provide that information to the public online. − In 2012, Range initiated a Zero Vapor Protocol for wet gas and super rich areas in Marcellus shale gas development.  Range provides training to its employees to create a culture of safe performance and regulatory compliance. Our Contractor Management protocol requires that work be performed at its highest standard.  Range remains active in incident management and response planning by working with local community government and first responders to identify roles and responsibilities for a robust unified management approach to unique situations.  Range’s goal is to maintain a safe and secure working environment for our employees and the communities in which we work. Environment, Health and Safety - A Core Value at Range
  • 28 Range – Significant Growth Potential for Many Years  2014 production growth expected to be 20%-25%  High rate of return, high growth, large scale assets, and low reinvestment risk  Large net acreage position, with stacked pay potential, in the Appalachian core areas allowing for durable future growth  Solid track record of execution, planning, marketing and logistics  Resource potential 8-10 times proved reserves 28
  • 29 Appendix 29
  • 30 30 Marcellus and Appalachia Section
  • 31 Shale Wells Drilled and Permitted Legend RANGE ANADARKO CHEVRON/CHIEF SW CABOT CHESAPEAKE CHIEF CONSOL ECA EOG EQT EXCO REX SHELL TALISMAN ULTRA XTO/EXXON/PHILLIPS OTHERS Legend Super-Rich Area Wet Area LARGER DOTS – DRILLED SMALLER DOTS – PERMITS
  • 32 Super-Rich 110,000 acres Southwest PA – Super-Rich Marcellus Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013)  Acreage provides the opportunity for condensate growth  In Q1 2014, Range drilled our highest rate Marcellus well to date - 24 hr 1P of 6,357 boe/d (38.1 Mmcfe/d) with 65% liquids  Planned 2014 activity in the super-rich is expected to use 5,300 foot laterals and RCS completions with expected recoveries of 2.05 Mmboe (12.3 Bcfe)  During 2014, Range plans to turn to sales 57 super-rich wells 32 • Previously drilled well
  • 33 SW PA Super-Rich Area Marcellus Projected Development Mode Economics  Southwestern PA – (high Btu case)  EUR – 2.05 Mmboe (12.3 Bcfe) (129 Mbbls condensate, 1,043 Mbbls NGLs, and 5.3 Bcf gas)  Drill and Complete Capital $6.8 MM  F&D – $4.00/boe 40% 60% 80% 100% 120% 140% $3.00 $4.00 $5.00 Gas Price, $/Mmbtu NYMEX IRR  Includes gathering, pipeline and processing costs  Oil price assumed to be $90.00/bbl with no escalation  NGL price (except for ethane) assumed to be 40% of WTI with escalation  Ethane price tied to ethane contracts plus same comparable escalation as gas price  Strip dated 12/31/13 with 10 year average $81/bbl and $4.33/mcf Strip pricing NPV10 = $15.0 MM NYMEX Gas Price 2.05 Mmboe Strip - 104% $3.00 - 81% $4.00 - 105% $5.00 - 132% Reserves and economics based on planned future activity of 5,300 foot lateral length with 26 frac stages, 500 klbs/stage 33
  • 34 Southwest PA – Super-Rich Marcellus 34 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2013 2014 2015 Feet Horizontal Length 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 0.1 0.2 0.3 0.4 0.5 2013 2014 2015 EUR(Mmboe)/1,000ft. EUR per 1,000 ft. 0.0 0.3 0.6 0.9 1.2 1.5 1.8 2.1 2.4 2013 2014 2015 EUR(Mmboe) EUR by Year Gas NGLs Condensate
  • 35 1 10 100 1,000 10,000 1 6 11 16 21 26 31 36 Bbls/dMcf/d Months Residue Gas OIL NGL (INCLUDES ETHANE) Southwest PA – Super-Rich Marcellus Well Projection 35 • EUR – 1,172 Mbbls & 5.3 BCF (2.05 Mmboe) • 5,300 foot lateral length • 26 frac stages Estimated Cumulative Recoveries Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 42 774 153 2 Years 62 1,260 248 3 Years 74 1,637 322 5 Years 90 2,213 436 10 Years 107 3,140 619 20 Years 119 4,235 834 EUR 129 5,300 1,043
  • 36 Southwest PA – Super-Rich Marcellus 2013 Well Performance 10 100 1,000 1 51 101 151 201 251 301 351 Liquids(Bbls/dper1,000')ResidueGas(Mcf/dper1,000') Days All production data normalized to 1,000 foot of lateral 2013 Type Curve (1.32 Mmboe) Normalized to 1,000' 2013 Type Curve (1.32 Mmboe) Normalized to 1,000' 2013 Actual Super Rich Well Performance (55 Wells) 2013 Actual Super Rich Well Perfomance (55 Wells) Residue Gas Liquids •2013 type curves based on 3,894' lateral length •55 wells performing approximately 50% above 2013 type curve after one year 2013 Program Year Super Rich Wells 2013 Program Year Super Rich Wells 2013 Super Rich Residue Gas TC (1.32 Mmboe) 2013 Super Rich Liquids TC (1.32 Mmboe)
  • 37  Over 200 Range wells placed on production in wet gas area over the last four years with varying lateral lengths and frac stages  Planned 2014 activity in the wet area is expected to use 4,200 foot laterals with RCS completions resulting in anticipated recoveries of 12.3 Bcfe  During 2014, Range plans to turn to sales 55 wet wells Southwest PA – Wet Marcellus Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013) 37 Super-Rich 110,000 acres Wet Gas 220,000 acres Dry Gas 200,000 acres • Previously drilled well
  • 38 SW PA Wet Marcellus Projected Development Mode Economics  Southwestern PA – (wet gas case)  EUR –12.3 Bcfe (27 Mbbls condensate, 951 Mbbls NGLs, and 6.4 Bcf gas)  Drill and Complete Capital $6.1 MM  F&D – $0.60/mcfe 40% 60% 80% 100% 120% 140% 160% $3.00 $4.00 $5.00 Gas Price, $/Mmbtu NYMEX IRR  Includes gathering, pipeline and processing costs  Oil price assumed to be $90.00/bbl with no escalation  NGL price (except for ethane) assumed to be 40% of WTI with escalation  Ethane price tied to ethane contracts plus gas price escalation  Strip dated 12/31/13 with 10 year average $81/bbl and $4.33/mcf Strip pricing NPV10 = $12.9 MM NYMEX Gas Price 12.3 Bcfe Strip - 107% $3.00 - 68% $4.00 - 105% $5.00 - 149% Reserves and economics based on planned future activity of 4,200 foot lateral length with 21 frac stages, 400 klbs/stage
  • 39 Southwest PA – Wet Marcellus 39 2,000 2,500 3,000 3,500 4,000 4,500 5,000 2013 2014 2015 Feet Horizontal Length 5 10 15 20 25 2013 2014 2015 Stages Average Number of Stages 1.0 1.5 2.0 2.5 3.0 3.5 2013 2014 2015 EUR(Bcfe)/1,000ft. EUR per 1,000 ft. 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 2013 2014 2015 EUR(Bcfe) EUR by Year Gas NGLs Condensate
  • 40 1 10 100 1,000 10,000 1 6 11 16 21 26 31 36 Bbls/dMcf/d Months Residue Gas OIL NGL (INCLUDES ETHANE) Southwest PA – Wet Marcellus Well Projection 40 • EUR – 978 Mbbls & 6.4 BCF (12.3 Bcfe) • 4,200 foot lateral length • 21 frac stages Estimated Cumulative Recoveries Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 11 1,082 161 2 Years 14 1,674 249 3 Years 17 2,117 315 5 Years 19 2,775 412 10 Years 23 3,841 571 20 Years 25 5,095 757 EUR 27 6,400 951
  • 41 Represent a 10+ Bcf well Represent a 5-10 Bcf well Southwest PA – Industry Activity in Dry Gas Acreage  56% of horizontal dry gas Marcellus wells drilled by industry in SW PA have projected recoveries from 5 to over 20 Bcf per well  Range’s SW Pennsylvania dry gas acreage is predominantly held by production  Range’s future wells are expected to be 5,200 foot laterals with RCS completions and anticipated recoveries of 13.4 Bcf Note: Townships where Range holds ~3,000 or more acres are shown in yellow (As of 12/31/2013) 200,000 net acres 41
  • 42 SW PA Dry Marcellus Projected Development Mode Economics  Southwestern PA – (dry gas)  EUR – 13.4 Bcf  Drill and Complete Capital $6.6 MM  F&D – $0.59/mcf – (13.4 Bcf) 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 220% $3.00 $4.00 $5.00 Gas Price, $/Mmbtu NYMEX IRR  Includes gathering, pipeline and processing costs  Strip dated 12/31/13 with 10 year average $4.33/mcf Strip pricing NPV10 = $12.4 MM NYMEX Gas Price 13.4 Bcf Strip - 117% $3.00 - 39% $4.00 - 104% $5.00 - 201% 42 Reserves and economics based on planned future activity of 5,200 foot lateral length with 26 frac stages, 300 klbs/stage
  • 43 43 Southwest PA – Dry Marcellus 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 2013 2014 2015 Feet Horizontal Length 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 2013 2014 2015 EUR(Bcf)/1,000ft. EUR per 1,000 ft. 0 2 4 6 8 10 12 14 16 2013 2014 2015 EUR(Bcf) EUR by Year Gas
  • 44 1 10 100 1,000 10,000 100,000 1 6 11 16 21 26 31 36 Mcf/d Months Residue Gas Southwest PA – Dry Marcellus Well Projection 44 • EUR – 13.4 BCF • 5,200 foot lateral length • 26 frac stages Estimated Cumulative Recoveries Residue (Mmcf) 1 Year 2,951 2 Years 4,218 3 Years 5,115 5 Years 6,406 10 Years 8,434 20 Years 10,772 EUR 13,400
  • 45 Marcellus Wet Gas Provides Significant Price Uplift $4.16 $3.92 $3.20 $1.53 $1.53 $1.95 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 Dry Gas Wet Gas - Ethane Rejection Wet Gas - Ethane Extraction Gas (1140 Btu) 14% shrink Condensate NGLs (C3+) Gas (1055 Btu) 24% shrink NGLs (C2+) $7.40 $7.70- $7.80 $2.97 - $3.07 Gas (1040 Btu) $4.16 $/Wellhead Mcf Assumptions: $4.00 NG, $90.00 WTI, 40% WTI (C3+), 2.27 GPM (ethane rejection), 5.60 GPM (ethane extraction), all processing, shrink, fuel & ethane transport included. Based on SWPA wet gas quality (1,275 processing plant inlet btu). Wet Gas (Ethane Extraction) based on full utilization of current ethane/propane agreements. NOTE: Wet Gas (Ethane Rejection) equals 1.3 mcfe post-processing and Wet Gas (Ethane Extraction) equals 1.68 mcfe. Current Projected - 2015 Condensate
  • 46 Ethane Ship Currently Being Used by Evergas Photo Courtesy of Evergas 46
  • 47 54% 4% 9% 8% Weighted Avg. Composite Barrel (1) Ethane C2 Propane C3 Iso Butane iC4 Normal Butane NC4 Natural Gasoline C5+ 25% (1) Based on estimated NGL volumes for 1Q 2014 (2) Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus Marcellus NGL Pricing 47 Realized Marcellus NGL Prices 2013 2014 1Q 2Q 3Q 4Q 1Q NYMEX – WTI (per bbl) $ 94.25 $ 94.20 $105.87 $97.48 $98.61 Mont Belvieu Weighted Priced Equivalent (2) $53.37 $50.26 $52.63 $47.78 $37.61 Plant Fees plus Differential (16.21) (17.33) (18.63) (11.91) (8.41) Average price before NGL hedges $37.16 $32.93 $34.00 $35.87 $29.20 % of WTI (NGL Pre-hedge / Oil NYMEX) 39% 35% 32% 37% 30% % of Mont Belvieu Weighted Equivalent 70% 66% 65% 75% 78%
  • 48 Realized Marcellus Condensate Prices Quarter Condensate bbls/d WTI Oil Price Marcellus Condensate Price Condensate as % of WTI 1Q 2012 3,395 $103.13 $83.54 81% 2Q 2012 3,434 $92.27 $77.51 84% 3Q 2012 4,422 $92.58 $79.05 85% 4Q 2012 6,047 $88.17 $76.57 87% 1Q 2013 6,457 $94.25 $82.56 88% 2Q 2013 6,216 $94.20 $80.41 85% 3Q 2013 7,368 $105.87 $86.54 82% 4Q 2013 7,889 $97.48 $79.37 81% 1Q 2014 8,292 $98.61 $81.59 83% Marcellus Condensate Pricing  Growing demand from Canada  Greater use as blending agent with refiners and petrochemical users Year Condensate Price as % of WTI 2010 63% 2011 79% 2012 84% 2013 84% 48
  • 49 Range Processing Capacity from MarkWest Liberty Wet Gas - SW  Currently 425 Mmcf/d firm cryo processing capacity plus unutilized third party capacity; processing capacity increases to 625 Mmcf/d by 2Q 2014 and 1,025 Mmcf/d subsequently (1) Unused capacity can be used by Range on an interruptible basis (2) Mobley, Sherwood and Bluestone (Mmcf/day) Houston Majorsville Other Total Current Range 355 70 425 Others 600 1,210 1,810 Future Range 400 200 600 Others 200 920 1,120 Total Range 755 270 1,025 Others 800 2,130 2,930 Total 755 1,070 2,130 3,955 49 (2)(1)(1)
  • 50 50 Processing Capacity Development Source: MarkWest Energy Partners, March 2014
  • 51  A 1-2 rig program is designed to hold all blocked up acreage being targeted for development  Planned 2014 activity in area is expected to use 4,600 foot laterals and 23 frac stages  In 2014, Range plans to turn 14 wells to sales in the northeast Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013) Northeast PA 51 Northeast 120,000 net acres
  • 52 Firm Transport & Sales with Firm Transport (Mmbtu/day) 2014 2016 SW PA Firm Transport 830,000 1,155,000 Firm Sales 115,000 370,000 NE PA Firm Transport 40,000 40,000 Firm Sales 125,000 160,000 TOTAL Firm Transport 870,000 1,195,000 Firm Sales 240,000 530,000 1,110,000 1,725,000 Marcellus Area Pipelines – Take-Away Capacity Columbia Gas Transmission/Columbia Gulf Texas Eastern Transmission Tennessee Gas Pipeline Dominion Transmission Transcontinental Gas Pipeline Areas under development Marcellus Fairway 52 Range will continue to layer on new firm transportation to meet our expected growth in gas production (1) (1) Excludes regional firm gathering to interstate pipelines
  • 53 Marcellus – Planned and Proposed Infrastructure Projects through 2016 53 Incremental capacity: +10.0 Bcfd Metropolitan NY Area Williams Rockaway Lateral +0.6 Bcfd North & Northeast Constitution Pipeline Williams NE Connector Spectra AIM Project +1.7 Bcfd *Data as of February 2014 *Capacities and timing may vary *May not include all current projects Mid-Atlantic & Southeast NiSource (TCO) East Side Expansion Williams Leidy SE Expansion Williams Atlantic Sunrise TETCO Team 2014 +3.1 Bcfd South & Southwest NiSource (TCO) West Side Expansion TETCO OPEN Project TETCO TEAM 2014 TETCO TEAM South TETCO Gulf Markets NiSource (TCO) Leach/Rayne Express +3.2 Bcfd West & Northwest TETCO/DTE/Enbridge NEXUS Pipeline TETCO Uniontown to Gas City +1.4 Bcfd
  • 54  Range has completed two 500 foot spaced pilot projects in the super-rich and wet areas of the Marcellus Shale in Washington County PA that have been online for three and a half years  Results from these projects have been very promising with EURs for 500 foot spaced wells averaging 80% of EURs for 1,000 foot spaced wells  Assuming full development of the super-rich and wet areas of the Marcellus, tighter spacing adds an incremental 12 to 15 Tcfe of resource potential  Dry gas areas also have tighter spacing potential 54 Tighter Spacing Adds 12 to 15 Tcfe in Super-Rich and Wet Areas
  • 55 55 0 500 1,000 1,500 2,000 2,500 3,000 1 365 729 1093 Mcfed/1,000ft. 500 ft Wells 1,000 ft Wells Year 1 Year 3Year 2 500 foot spaced wells produced 80% of 1,000 foot spaced wells over a three and a half year period Production includes residue gas, condensate and NGLs Projects conducted in the Super-Rich and Wet areas of the Marcellus Results of Marcellus Tighter Spacing Pilot Projects
  • 56 Range Virginia Assets  Producing ~72 Mmcf/day – very low decline rate  Interest in over 3,000 producing wells  9,000+ additional wells to drill  Stacked pay area  Location is strategic to expanding markets in the southeast  3.2 to 3.6 Tcf resource potential 56 Mineral Rights HBP HBP + Royalty Note: Acreage shown (As of 12/31/2013) Virginia 230,000 net acres
  • 57 57 Midcontinent Section
  • 58 Oklahoma / Kansas – Mississippian Chat  Over 4,500 Mississippian wells have defined the productive boundaries  On 80 acre spacing Range has the opportunity to drill ~2,000 potential horizontal wells  Mississippian could equate to almost a billion barrel equivalent field net for Range  Highest average cumulative oil production from vertical wells are located in Kay County; Cowley & Sumner counties are also high • Represent historic vertical Mississippian wells Note: Sections where Range has acreage are shown in yellow (As of 12/31/2013), and average cumulative oil production per vertical well shown in maroon text Range’s ~160,000 net acres appear prospective based on vertical well control *Internal estimates indicate 64 MBO cumulative production for Cowley County wells. Based on data from 598 wells with first production prior to 12/31/1985. * 58
  • 59 NEMAHA RIDGE (Uplift) Location is Important  Our location on the Nemaha Uplift offers enhanced Chat development, as well as a favorable structural position  Chat porosity ranges up to 30% - 40% while Mississippi Lime porosity falls in the 3% - 5% range on average  Higher structurally, generally giving way to better oil cuts Range has ~160,000 Net Acres on or in Close Proximity to the Nemaha Ridge Pennsylvania Formations Chat West East 59
  • 60 Avg. Cum. Oil Production per Well from Mississippian Based on industry reporting sources *Internal estimates indicate 64 MBO cumulative production for Cowley County wells. Based on data from 598 wells with first production prior to 12/31/1985. * Highest average cumulative oil production from vertical wells are located in Kay County 60
  • 61 0% 20% 40% 60% 80% 100% 120% 140% $80.00 $90.00 $100.00 61 Mississippian Chat Development Mode Economics  Based on recent completion designed wells  EUR – 485 Mboe - 600 Mboe  Drill & Complete Capital $3.7 MM − All cases include $200K for SWD  F&D – $9.86/boe – (485 Mboe) $8.06/boe – (600 Mboe) Oil Price, $/bbl NYMEX IRR NYMEX Oil Price 485 Mboe 600 Mboe Strip - 59% 107% $ 80.00 - 45% 81% $ 90.00 - 56% 100% $100.00 - 69% 121%  Includes gathering, pipeline and processing costs  Strip dated 12/31/13 with 10 year average $81.13/bbl and $4.33/mcf  Gas price assumed to be $4.00/mcf in all scenarios Strip Pricing NPV10 = $3.7 MM (485 Mboe) Strip Pricing NPV10 = $6.7 MM (600 Mboe)
  • 62 10 100 1,000 0 100 200 300 400 500 600 700 800 Days Gas Average Ngl Average Oil Average BOE Average 485 MBOE Gas Type 485 MBOE Ngl Type 485 MBOE Oil Type 485 MBOE Equiv Type 600 MBOE Gas Type 600 MBOE Ngl Type 600 MBOE Oil Type 600 MBOE Equiv Type 62 Mississippian Type Curves By Product – Larger Frac Note: Fewer number of wells included in data set moving left to right Larger Stimulation Design - 6 wells average EUR is 600 Mboe - 3,800 foot laterals and 19 stages - 70% of EUR comprised of Crude Oil and NGL with full Cryo Recoveries - EUR equates to 7-14% recovery of the original oil in place Bbls/dayMmcf/day
  • 63 Concentrated Position Allows Low Cost Future Development Rodman Plant – Mustang Capacity: 70 Mmcf/d; up to 140 Mmcf/d with offloads to other Mustang Plants Residue Pipelines: OK-Tex (connected to OGT, Enogex, CEGT, PEPL and Southern Star) Bellmon Plant – Superior Capacity: 30 Mmcf/d and expanding Residue Pipeline: Southern Star  Range has ~160,000 net acres largely blocked up for economy of scale  Gas processing and crude oil refining are all adjacent to acreage  Oil ~40 gravity  Capacity is scalable as production grows  Firm transport provided in connection with processing agreements Conoco Phillips crude oil refinery Capacity: 200,000 Bbls/d 63 Note: Acreage shown (As of 12/31/2013)
  • 64 64 Financial and Reserve Section
  • 65 Strong, Simple Balance Sheet Year-End 2010 Year-End 2011 Year-End 2012 Year-End 2013 1st Quarter 2014 ($ in millions) Bank borrowings $274 $187 $739 $500 $594 Sr. Sub. Notes 1,686 1,788 2,139 2,641 2,641 Less: Cash (3) (0) (0) (0) (0) Net debt 1,957 1,975 2,878 3,141 3,235 Common equity 2,224 2,392 2,357 2,414 2,450 Total capitalization $4,181 $4,367 $5,235 $5,555 $5,685 Debt-to- capitalization(1) 47% 45% 55% 57% 57% Debt/EBITDAX(1) 2.8x 2.3x 3.2x 2.8x 2.8x Liquidity(2) $ 971 $ 1,284 $ 927 $1,166 $1,029 (1) Ratios are net of cash balances. (2) Liquidity equals cash available borrowings under the revolving credit facility, as requested. 65
  • 66 Debt Maturities $594 $300 $500 $500 $600 $750 0 100 200 300 400 500 600 700 800 Senior Secured Revolving Credit Facility (as of March 31, 2014) Senior Subordinated Notes Range maintains an orderly debt maturity ladder ($Millions) Credit Facility 1Q14 66
  • 67 Range’s Outstanding Bonds Corporate Rating: Ba1 / BB Outlook: Stable Range bonds have consistently traded in-line or better than BB rated index 67 Senior Subordinated Notes Amount Current YTW 8.00% due 2019 $ 300 0.94% 6.75% due 2020 $ 500 2.83% 5.75% due 2021 $ 500 3.62% 5.00% due 2022 $ 600 4.85% 5.00% due 2023 $ 750 4.94% Total $2,650 Source: Bank of America as of 2/14/14 Note: Range’s weighted average maturity is 8 years (excluding notes callable in 2014) (1) Excludes notes due 2019 given May 2014 first call date 4.19% 4.44% 5.81% 5.61% 0.00% 1.00% 2.00% 3.00% 4.00% 5.00% 6.00% 7.00% Range Weighted Average (1) BB Index 7 to 10 Year Maturity Index E&P Index YieldtoWorst
  • 68 $0.70 $0.90 $1.10 $1.30 $1.50 2008 2009 2010 2011 2012 2013 $- $0.20 $0.40 $0.60 $0.80 $1.00 2008 2009 2010 2011 2012 2013 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 2008 2009 2010 2011 2012 2013 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 2008 2009 2010 2011 2012 2013 Resilient Credit Metrics Driven by Low Cost Growth Debt / EBITDAX Debt / Total Proved ($/mcfe) Debt / Production ($/boepd) Debt / Proved Developed ($/mcfe) Covenant BB / Ba2 Peer Average for 2012 BB / Ba2 Peer Average for 2012 BB / Ba2 Peer Average for 2012
  • 69 Volumes Hedged Average Floor Price Average Cap Price (Mmbtu/day) ( $ / Mmbtu) ( $ / Mmbtu) 2Q 2014 Swaps 200,000 $4.17 2Q 2014 Collars 447,500 $3.84 $4.48 3Q 2014 Swaps 260,000 $4.18 3Q 2014 Collars 447,500 $3.84 $4.48 4Q 2014 Swaps 260,000 $4.18 4Q 2014 Collars 447,500 $3.84 $4.48 2015 Swaps 277,432 $4.21 2015 Collars 145,000 $4.07 $4.56 2016 Swaps 72,500 $4.19 Gas Hedging Status 69 As of 04/22/2014
  • 70 Volumes Hedged Average Floor Price Average Cap Price (bbls/day) ($/bbl) ($/bbl) 2Q 2014 Swaps 8,500 $94.51 2Q 2014 Collars 2,000 $85.55 $100.00 3Q 2014 Swaps 9,500 $94.35 3Q 2014 Collars 2,000 $85.55 $100.00 4Q 2014 Swaps 9,500 $94.35 4Q 2014 Collars 2,000 $85.55 $100.00 2015 Swaps 6,496 $89.70 Oil Hedging Status 70 As of 04/22/2014
  • 71 Volumes Hedged Hedged (1) Price Propane (C3) Volumes Hedged Hedged (1) Price (bbls/day) ($/gal) (bbls/day) ($/gal) Natural Gasoline (C5) 2Q 2014 Swaps 1,000 $2.113 2Q 2014 Swaps 12,000 $1.016 3Q 2014 Swaps - - 3Q 2014 Swaps 12,000 $1.018 4Q 2014 Swaps - - 4Q 2014 Swaps 12,000 $1.018 Normal Butane (NC4) Ethane (C2) 2Q 2014 Swaps 4,000 $1.344 2Q 2014 Swaps - - 3Q 2014 Swaps 4,000 $1.344 3Q 2014 Swaps - - 4Q 2014 Swaps 4,000 $1.344 4Q 2014 Swaps - - Natural Gas Liquids Hedging Status (1) NGL hedges have Mont Belvieu as the underlying index.As of 04/22/2014 Conversion Factor: One barrel = 42 gallons 71
  • 72 72 16% 78% 6% Budget = $1.52 Billion Drilling Acreage & Seismic Pipelines, Facilities & Other Budget by Area Marcellus Permian Midcontinent Appalachia / Nora 87% 8% 2014 Capital Budget
  • 73 Eleven Years of Double-Digit Production Growth 0 200 400 600 800 1,000 1,200 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E Mmcfe/d Includes impact of acquisitions and asset sales 20%-25% Growth Projected for 2014 73
  • 74 Outstanding 2013 Reserve Performance Proved Reserves Walk Forward Bcfe Balance at December 31, 2012 6,506 ▪ Discoveries and extensions 1,733 ▪ Purchases - ▪ Revisions – performance Improved recovery PUD 630 PUD removal (374) Field performance PDP 111 Total performance revision 367 ▪ Revisions - pricing 81 ▪ Sales (142) ▪ Production (343) Balance at December 31, 2013 8,202 74 2013 Performance  26% year-over-year increase • Crude oil/condensate and NGL reserve volumes increased 48%  612% reserve replacement  $0.61 per mcfe all-in finding and development cost  $0.57 per mcfe drill bit finding cost  51% Proved developed
  • 75 Growth at Low Cost (1) Includes performance revisions only. (2) From all sources, including price and performance revisions, excludes sales. (3) Beginning in 2009, amounts based upon new SEC rules as to pricing and PUD methodology. (4) Percentages shown are compounded annual growth rates Top quartile growth at top quartile cost 75 2009(3) 2010 2011 2012 2013 3 Year Average 5 Year Average Reserve growth 18% 42% 14% 29% 26% 23%(4) 25%(4) Drill bit replacement (1) 540% 840% 850% 773% 612% 725% 718% All sources replacement (2) 486% 931% 849% 680% 636% 703% 709% Drill bit only - without acreage (1) $0.69 $0.59 $0.76 $0.67 $0.57 $0.66 $0.65 Drill bit only - with acreage (1) $0.90 $0.70 $0.89 $0.76 $0.63 $0.75 $0.76 All sources - Excluding price revisions $0.90 $0.73 $0.89 $0.76 $0.63 $0.75 $0.76 Including price revisions $1.00 $0.71 $0.89 $0.86 $0.61 $0.77 $0.78
  • 76 76  Consumer Savings  Shale production could save U.S. households up to as much as $113 billion a year per through 2015(1)  Average US household will save up to $725 each year, savings could potentially rise to as much as $1,200 a year by 2020 (2)  Added more than $1,200 last year to the income of the average U.S. family (3)  Per EIA, natural gas will supply 46% of all new power plants built through 2035, further increasing savings  Manufacturing American Products: Low feedstock and energy prices  Could result in 1 million additional American factory jobs by 2025(4)  Save U.S. manufacturers as much as $11.6 billion annually(4)  Other industries: chemical, pharmaceuticals, etc.  Family-Sustaining High-Paying Jobs  1,345,513 direct and indirect jobs created by the U.S. Natural Gas Industry (5)  Currently in PA: 241,926 jobs with an average salary of $84,400 (6)  From 2005-2012, almost 90% of job growth in Pennsylvania came from oil and gas jobs in the upstream and midstream (7)  Natural Gas as a Transportation Fuel: CNG & LNG  Cleaner-burning – about 25% lower carbon dioxide emissions  Cheaper – Costs about 50% less than gasoline  CNG fleet conversions are increasing Why Natural Gas? 1. U.S. Federal Reserve economists 2. IHS September 2013 3. The Boston Consulting Group 4. PricewaterhouseCoopers 2012 Study 5. U.S. Natural Gas Caucus 6. PA Department of Labor and Industry (December 2013) 7. Raymond James
  • 77 77  Water Usage: − Least water consumptive energy resources per MMBTU at 0.6-5.8 gallons(1)  Nuclear: 8-14  Oil: 8-20 gallons  Coal: 13-32 gallons  Biodiesel from soy: 14,000-75,000 gallons  Surface Impact: Access to hundreds of acres from one location − Total surface disturbance during drilling, including access road, pad and required pipeline infrastructure is less than 1%  Air Quality: 2006-2012: Natural gas grew to provide 30% of electricity in the U.S. (2) − During that time, U.S. has recorded the world’s largest decline in greenhouse-gas emissions, reducing 450 million tons − The U.S. has dropped CO2 emissions by 500 megatons – about 2x the entire global reductions over the past 20 years(3) − PA air quality has significantly improved since 2008 because of increased use of natural gas for power generation. Improved air quality translates to $14 billion to $37 billion in annual public health benefits(4) Natural Gas – Less Environmental Impact 1. U.S. Federal Reserve economists 2. EIA 3. PricewaterhouseCoopers 2012 Study 4. Pennsylvania DEP
  • 78 Contact Information Range Resources Corporation 100 Throckmorton, Suite 1200 Fort Worth, Texas 76102 Main: 817.870.2601 Fax: 817.870.2316 Rodney Waller, Senior Vice President rwaller@rangeresources.com David Amend, Investor Relations Manager damend@rangeresources.com Laith Sando, Research Manager lsando@rangeresources.com Michael Freeman, Financial Analyst mfreeman@rangeresources.com www.rangeresources.com 78